Arrangement and method for regulating bottom hole pressures when drilling deepwater offshore wells

ABSTRACT

An arrangement and a method to control and regulate the bottom hole pressure in a well during subsea drilling at deep waters: The method involves adjustment of a liquid/gas interface level in a drilling riser up or down. The arrangement comprises a high pressure drilling riser and a surface BOP at the upper end of the drilling riser. The surface BOP havs a gas bleeding outlet. The riser also comprises a BOP, with a by-pass line. The drilling riser has an outlet at a depth below the water surface, and the outlet is connected to a pumping system with a flow return conduit running back to a drilling vessel/platform.

FIELD OF THE INVENTION

The present invention relates to a particular arrangement for use whendrilling oil and gas wells from offshore structures that float on thesurface of the water in depths typically greater than 500 m aboveseabed. More particularly, it describes a drilling riser system soarranged that the pressure in the bottom of an underwater borehole canbe controlled in a completely novel way, and that the hydrocarbonpressure from the drilled formation can be handled in an equally new andsafe fashion in the riser system itself.

BACKGROUND OF THE INVENTION

This invention defines a particular novel arrangement, which can reducedrilling costs in deep ocean and greatly improve the safe handling ofthe hydrocarbon gas or liquids that may escape the subsurface formationbelow seabed and then pumped from the subsurface formation with thedrilling fluid to the drilling installation that floats on the oceansurface. By performing drilling operations with this novel arrangementas claimed, there is provided a complete new way of controlling thepressure in the bottom of the well and at the same time safely andefficiently handling hydrocarbons in the drilling riser system. Thearrangement comprises the use of prior known art but arranged so thattotally new drilling methods is achieved. By arranging the varioussystems coupled to the drilling riser in this particular way, totallynew and never before used methods can be performed safely in deepwater.The invention relates to a deep water drilling system, and morespecifically to an arrangement for use in drilling of oil/gas wells,especially for deep water wells, preferably deeper than 500 mwater-depth.

Experience from deepwater drilling operations has shown that thesubsurface formations to be drilled usually have a fracture strengthclose to that of the pressure caused by a column of seawater.

As the hole deepens the difference between the formation pore pressureand the formation fracture pressure remains low. The low margin dictatesthat frequent and multiple casing strings have to be set in order toisolate the upper rock sections that have lower strength from thehydraulic pressure exerted by the drilling fluid that is used to controlthe larger formation pressures deeper in the well. In addition to thestatic hydraulic pressure acting on the formation from a standing columnof fluid in the well bore there are also the dynamic pressures createdwhen circulating fluid through the drill bit. These dynamic pressuresacting on the bottom of the hole are created when drill fluid is pumpedthrough the drill bit and up the annulus between the drill string andformation. The magnitude of these forces depends on several factors suchas the rheology of the fluid, the velocity of the fluid being pumped upthe annulus, drilling speed and the characteristics of the wellbore/hole. Particularly for smaller diameter hole sizes these additionaldynamic forces become significant. Presently these forces are controlledby drilling relatively large holes thereby keeping the annular velocityof the drilling fluid low and by adjusting the rheology of the drillingfluid. The formula for calculating these dynamic pressures is stated inthe following detailed description. This new pressure seen by theformation in the bottom of the hole caused by the drilling process isoften referred to as Equivalent Circulating Density (ECD).

In all present drilling operations to date in offshore deepwater wells,the bottom of the well will observe the combined hydrostatic pressureexerted by the column of fluid from the drilling vessel to the bottom ofthe well, plus the additional pressures due to circulation. A drillingriser that connects the seabed wellhead with the drilling vesselcontains this drilling fluid. The bottom-hole pressure to overcome theformation pressure is regulated by increasing or decreasing the densityof the drilling fluids in conventional drilling until the casing has tobe set in order to avoid fracturing the formation.

In order to safely conduct a drilling operation there has to be aminimum of two barriers in the well. The primary barrier will be thedrilling fluid in the borehole with sufficient density to control theformation pressure, also necessary in the event that the drilling riseris disconnected from the wellhead. This difference in pressure caused bythe difference in density between seawater and the drilling fluid can besubstantial in deep water. The second barrier will be the blowoutpreventer BOP (BOP) in case the primary barrier is lost.

As the drilling fluid must have a specific gravity such that the fluidremaining in the well is still heavy enough to control the formationwhen the drilling marine riser is disconnected, this creates a problemwhen drilling in deep waters. This is due to the fact that the marineriser will be full of heavy mud when connected to the sub sea blowoutpreventer, causing a higher bottom-hole pressure than required forformation control. This results in the need to set frequent casings inthe upper part of the hole since the formation cannot support the highermudweight from the surface.

In order to be able to drill wells with a higher density drilling fluidthan necessary, multiple casings will be installed in the borehole forisolation of weak formation zones.

The consequences of multiple casing strings will be that each new casingreduces the borehole diameter. Hence the top section must be large inorder to drill the well to its planned depth. This also means thatslimhole or slender wells are difficult to construct with presentmethods in deeper waters.

Normally it is not possible to control the pressure from the surface ina conventional drilling operation, due to the fact that the well returnswill flow into an open flow line at atmospheric pressure. In order toobtain wellhead pressure control, the well return has to be routedthrough a closed flow line by way of a closed blow out preventer to achoke manifold. The advantage of controlling bottom hole pressure bymeans of wellhead pressure control is that a pressure change at thesurface results in an almost instantaneous pressure response at thebottom of the hole when a single-phase drilling fluid is used. Ingeneral, the surface pressure should be kept as low as possible toobtain safer working environment for the personnel working on the rig.So, it is preferable to control the well by changing pressures in thewell bore to the largest extent. Conventionally, this can be performedby means of hydrostatic pressure control and friction pressure controlin the annulus.

Hydrostatic pressure control is the prime means of bottom hole pressurecontrol in conventional drilling. The mud weight will be adjusted sothat the well is in an overbalanced condition in the well when nodrilling fluid circulation takes place. If needed, the mudweight/density can be changed depending on formation pressures. However,this is a time consuming process and requires adding chemicals andweighting materials to the drilling mud.

The other method for bottom hole pressure control is friction pressurecontrol. Higher circulating rates generates higher friction pressure andconsequently higher pressures in the bore hole. A change in pump ratewill result in a rapid change in the bottom hole pressure (BHP). Thedisadvantage of using frictional pressure control is that control islost when drilling fluid circulation is stopped. Frictional pressureloss is also limited by the maximum pump rate, the pressure rating ofthe pump and by the maximum flow through the down hole assembly.

The only reference referring to neutralization of ECD effects is foundin SPE paper LIDC/SPE 47821. Reference in this paper is made to WO99/18327.

All and each of the above references are hereby incorporated byreference.

SUMMARY OF THE INVENTION

The above prior art has many disadvantages. The object of the presentinvention is to avoid some or all of the disadvantages of the prior art.

Below some aspects of the present invention will be indicated.

In one aspect the present invention in a particular combination givesrise to new, practically feasible and safe methods of drilling deepwaterwells from floating structures. In this aspect benefits over the priorart are achieved with improved safety. More precisely the inventiongives instructions on how to control the hydraulic pressure exerted onthe formation by the drilling fluid at the bottom of the hole beingdrilled by varying the liquid level in the drilling riser.

In another aspect the invention gives a particular benefit in wellcontrolled situations (kick handling) or for planned drilling of wellswith hydrostatic pressure from drilling fluid less that the formationpressure. This can involve continuous production of hydrocarbons fromthe underground formations that will be circulated to the surface withthe drilling fluid. With this novel invention, both kick and handling ofhydrocarbon gas can be safely and effectively controlled.

In still another aspect of the invention the riser liquid level will belowered to a substantial depth below the sea-level with air or gasremaining in the riser above said level.

In contrast to prior art dual gradient systems an aspect of the presentinvention uses a single liquid gradient system, preferably drillingfluid (mud and/or completion fluid), with a gas (air) column on top.

In still another aspect the present invention has the combination ofboth a surface and a subsurface pressure containment (BOP). The presentinvention differs in this respect from U.S. Pat. No. 4,063,602 in thatit includes the following features: a high pressure riser with apressure integrity high enough to withstand a pressure equal to themaximum formation pressure expected to be encountered in the sub surfaceterrain, typically 3000 psi (200 bars) or higher; the riser isterminated in both ends by a high pressure containment system, such as ablow-out preventer; an outlet from the riser to a subsea pump system,typically substantially below the sea level and substantially above theseabed, which contains a back-pressure or non-return check valve; thesub-sea blowout preventer has an equalizing loop (by-pass) that willbalance pressure below and above a closed subsea BOP, wherein theequalizing loop connects the subsea well with the riser; the loop has atleast one, and preferably two, surface controllable valve(s).

There may be at least one choke line in the upper part of the drillingriser of equal or greater pressure rating than the drilling riser.

By incorporating the above features a well functioning system will beachieved that can safely perform drilling operations. The equalizingline can be used in a well control situation when and if a large gasinflux has to be circulated out of the well.

In the present invention the high pressure riser and a high pressuredrilling pipe may be so arranged between the subsea blowout preventerand the surface blowout preventer that they can be used as separate highpressure lines as a substitute for choke line and kill line.

In still another aspect the present invention incorporates thisequalizing loop in combination with a lower than normal air/liquidinterface level in the riser for well control purposes. This feature maybe combined with a particular low level of drilling fluid in the riser.The well may not be closed in at the surface BOP while drilling with alow drilling fluid level in the riser, since it can take too long beforethe large amount of air would compress or the liquid level in the risermight not raise fast enough to prevent a great amount of influx cominginto the well if a kick should occur. Hence, according to an aspect ofthe present invention, the well is closed in at the subsea BOP. However,since a high pressure riser with no outside kill and choke lines fromthe subsea BOP to the surface is used, the bypass loop is included inorder to have the ability to circulate out a large influx past a closedsubsea BOP into the high pressure riser. If the influx is gas, this gascan be bled off through the choke line in or under the closed surfaceBOP while the liquid is being pumped up the low riser return conduitthrough the low riser return outlet. This low riser return conduit andoutlet has preferably a “gas-lock” U-tube form below the subsea returnpumps, which will prevent the substantial part of the gas from beingsucked into the pump system. If only small amount of hydrocarbon gas ispresent in the drilling riser, an air/gas compressor is installed in thenormal flowline on surface, which will suck air from inside the drillingriser, creating a pressure below that of the atmospheric pressure abovethe riser. The compressor will discharge the air/gas to the burner boomor other safe gas vents on the platform. In still another aspect theliquid level (drilling mud) is kept relatively close to the outlet andthe gas pressure is close to atmospheric pressure, resulting in aseparation of the major part of the gas in the riser. The riser will inthis aspect of the invention become a gas separation chamber.

In still another aspect of the invention the bypass loop in combinationwith the low riser return outlet will also give rise to many otheruseful and improved methods of kick, formation testing and contingencyprocedures. Hence this combination is a unique feature of the invention.

In still another aspect of the present invention, the bottom holepressure is regulated without the need of a closed pressure containmentelement around the drill string anywhere in the system. Pressurecontainment will only be required in a well control situation or ifpre-planned under-balanced drilling is being performed. The presentinvention specifies how the bottom hole pressure can be regulated duringnormal drilling operation and how the ECD effects can be neutralized.

The present invention presents the unique combination of a high-pressureriser system and a system with pressure barriers both on surface and onseabed, which coexists with the combination of a low level returnsystem. The invention gives the possibility to compensate for bothpressure increases (surge) and decreases (swab) effects from runningpipe into the well or pulling pipe out of the well, in addition to andat the same time compensate for the dynamic pressures from thecirculation process ECD . The invention relates in this aspect to howthis control will be performed.

In an aspect the present invention overcomes many disadvantages of otherattempts and meets the present needs by providing methods andarrangements whereby the fluid-level in the high pressure riser can bedropped below sea level and adjusted so that the hydraulic pressure inthe bottom of the hole can be controlled by measuring and adjusting theliquid level in the riser in accordance with the dynamic drillingprocess requirements. Due to the dynamic nature of the drilling processthe liquid level will not remain steady at a determined level but willconstantly be varied and adjusted by the pumping control system. Theliquid level can be anywhere between the normal return level on thedrilling vessel above the surface BOP or at the depth of the low riserreturn section outlet. In this fashion the bottom-hole pressure iscontrolled with the help of the low riser return system. A pressurecontrol system controls the speed of the subsea mud lift pump andactively manipulates the level in the riser so that the pressure in thebottom of the well is controlled as required by the drilling process.

The arrangements and methods of the present invention represents instill another aspect a new, faster and safer way of regulating andcontrolling bottom hole pressures when drilling offshore oil and gaswells. With the methods described it is possible to regulate thepressure in the bottom of the well without changing the density of thedrilling fluid. The ability to control pressures in the bottom of thehole and at the same time and with the same equipment being able tocontain and safely control the hydrocarbon pressure on surface makes thepresent invention and riser system completely new and unique. Thecombination will make the drilling process more versatile and give roomfor new and improved methods for drilling with bottom hole pressuresless than pressure in the formation, as in under-balanced drilling.

The liquid/air interface level can also be used to compensate forfriction forces in the bottom of the well while cementing casing andalso compensate for surge and swab effects when running casing and/ordrill pipe in or out of the hole while continuously circulating at thesame time. To demonstrate this, the level in the annulus will be lowerwhen pumping through the drill pipe and up the annulus than it will bewhen there is no circulation in the well. Similarly, the level will behigher than static when pulling the drill bit and bottom-hole assemblyout of the open hole to compensate for the swabbing effect when pullingout of a tight hole.

The method of varying the fluid height can also be used to increase thebottom-hole pressure instead of increasing the mud density. Normally asdrilling takes place deeper in the formations the pore pressure willalso vary. In conventional drilling operation the drilling mud densityhas to be adjusted. This is time-consuming and expensive since additiveshave to be added to the entire circulating volume. With the low riserreturn system (LRRS) the density can remain the same during the entiredrilling process, thereby reducing time for the drilling operations andreducing cost.

In contrast to the prior art, the level in the riser can be dropped atthe same time as mud-weight is increased so as to reduce the pressure inthe top of the drilled section while the bottom hole pressure isincreased. In this way it is possible to reduce the pressure on weakformations higher up in the hole and compensate for higher porepressures in the bottom of the hole. Thus it is be possible to rotatethe pressure gradient line from the drilling mud around a fixed point,for example the seabed or casing shoe.

The advantage is that if an unexpected high pressure is encountered deepin the well, and the formation high up at the surface casing shoe cannotsupport higher riser return level or higher drilling fluid density atpresent return level, this can be compensated for by dropping the levelin the riser further while increasing the mud weight. The combinedeffect will be a reduced pressure at the upper casing shoe while at thesame time achieving higher pressure at the bottom of the hole withoutexceeding the fracture pressure below casing.

Another example of the ability of this system is to drill severelydepleted formations without needing to turn the drilling fluid into gas,foam or other lighter than water drilling systems. A pore pressure of0.7 SG (specific gravity) can be neutralized by low liquid level withseawater of 1.03 SG. This ability gives rise to great advantages whendrilling in depleted fields, since reducing the original formationpressure 1.10 SG to 0.7 SG by production, can also give rise to reducedformation fracture pressure, that can not be drilled with seawater fromsurface. With the present invention the bottom-hole pressure exerted bythe fluid in the well bore can be regulated to substantially below thehydrostatic pressure for water. With the prior art of drillingarrangements this will require special drilling fluid systems withgases, air or foam. With the present invention this can be achieved withsimple seawater drilling fluid systems.

However and additionally, the system can be used for creatingunder-balanced conditions and to safely drill depleted formations in asafer and more efficient way than by radically adjusting drilling fluiddensity, as in conventional practice. In order to achieve this and inorder to drill safely and effectively, the apparatus must be designedaccording to the present invention. The economical savings come from thenovel combination according to the present invention.

The system can be used for conventional drilling with a surface BOP withreturns to the vessel or drilling installation as normal with many addedbenefits in deepwater. The sub sea BOP can be greatly simplifiedcompared to prior art where there is a sub sea BOP only. In the presentinvention the subsea BOP can be made smaller than conventional sincefewer casings are needed in the well. Also since several functions, suchas the annular preventer and at least one pipe ram is moved to thesurface BOP on top of the drilling riser above sea-level, the totalsystem is less expensive and will also open the way for new improvedwell control procedures. In addition there are no longer need foroutside kill and choke lines running from the surface to the subsea BOPas in conventional drilling systems.

By having a surface blowout preventer on top of the drilling riser, allhydrocarbons can safely be bled off through the drilling rig's chokeline manifold system.

Another aspect of the present invention is a loop forming a“water/gas-lock” in the circulating system below the subsea mudliftpump, which will prevent large amount of hydrocarbon gases from invadinginto the pump return system. The height of the pump section can easilybe adjusted since it can be run on a separate conduit, thereby adjustingthe height of the water lock. By preventing hydrocarbon gas entering thereturn conduit, the subsea mud return pump will operate moreefficiently, and the rate at which the return fluid is pumped up theconduit can be controlled more precisely.

During normal operation the drilling riser will preferably be kept opento the atmosphere so that any vapour from hydrocarbons from the wellwill be vented off in the drilling riser. An air compressor will suckair/gas from the top of the drilling riser to the burner boom or othersafe air vents on the drilling installation, and create a pressure belowthat of atmospheric pressure in the top of the riser system. Since thepressure in the drilling riser at the low riser return outlet line willbe close to that of atmospheric pressure and substantially below thepressure in the pump return line, the majority of the gas will beseparated from the liquid. If large amount of gases is released from thedrilling mud in the riser, the surface BOP will have to be closed andthe gas bled off through the chokeline 58 to the choke manifold system(not shown) on the drilling rig. A rotating head can be installed on thesurface BOP hence the riser system can be used for continuous drillingunder-balanced and gas can be handled safely by also having stripperelements arranged in the surface BOP system. Hence, this system can beused for under-balanced drilling purposes and can also be used fordrilling highly depleted zones without having the need for aerated orfoamed mud. This arrangement will make the riser function as a gasknockout or first stage separator in an under-balanced or near balancedrilling situation. This can save space topside, since the majority ofgas is already separated and the return fluid is at atmospheric pressureat surface, meaning that the return fluid can be routed to the rig'sconventional mud gas separator or “Poor-Boy degasser” from the subseamud lift pump. For extreme cases the return fluid from the subsea mudreturn pumps might have to be routed through the choke manifold on thedrilling rig or tender assist vessel alongside the drilling rig.

By using this novel drilling method and apparatus, great cost savingsand improved well safety can be achieved compared to conventionaldrilling. The present invention will mitigate adverse effects of theprior art and at the same time open the way for new and never beforepossible operations in deeper waters.

If an under-balanced situation arises whereby the formation pressure isgreater than the pressure exerted by the drilling fluid, and formationfluid is unexpectedly introduced into the well-bore, then the well canbe controlled immediately with the arrangements and methods of thepresent invention by simply raising the fluid level in the high pressureriser. Alternately the well can be shut in with the subsea BOP. With thehelp of the by-pass line in the subsea BOP, the influx can be circulatedout of the well and into the high pressure riser under constantbottom-hole pressure equal to the formation pressure. The potential gasthat will separate out at the liquid/gas level (close to atmosphericpressure) in the riser will be vented out and controlled with thesurface BOP.

The riser of the arrangements of the present invention preferably has nokill or chokes line, which is contrary to what is normal for most marinerisers. Instead the annulus between the drill pipe and the riser becomesthe choke line and the drill pipe becomes the kill line when needed whenthe subsea BOP is closed. This will greatly increase the operator'sability to handle unexpected pressures or other well control situations.

The arrangements and methods of the present invention, will in aspecific new way make it possible to control and regulate thehydrostatic pressure exerted by the drilling fluid on the subsurfaceformations. It will be possible to dynamically regulate the bottom-holepressure by lowering the level down to a depth below sea level.Bottom-hole pressures can be changed without changing the specificgravity of the drilling fluid. It will now be possible to drill anentire well without changing the density of the drilling fluid eventhough the formation pore-pressure is changing. It will also be possibleto regulate the bottom-hole pressure in such a way that it cancompensate for the added pressures due to fluid friction forces actingon the borehole while pumping and circulating drilling mud/fluidsthrough a drill bit, up the annulus between the open hole/casing and thedrill pipe.

The invention is also particularly suitable for use with coiled tubingapparatus and drilling operations with coiled tubing. The presentinvention will also be specifically usable for creating “underbalance”conditions where the hydraulic pressure in the well bore is below thatof the formation and below that of the seawater hydrostatic pressure inthe formation.

Hence having a distinct liquid level low in the well/riser and a low gaspressure in the wellbore/riser that in sum balances out the formationpressure, will not only make it possible to drill in-balance fromfloating rigs, it will to the a person of skill in the art open up acomplete new set of possibilities that can not be achieved in shallowwater or on land.

Since the drilling riser can be disconnected from a closed subsea BOP,it can be safer to drill under-balanced than from other installationsthat does not have this combination. The reason also is that the gaspressure in the riser is very low and will cause the drill string to be“pipe heavy” at all times, excluding the need for snubbing equipment or“pipe light” inverted slips in the drilling operation. If pressure buildup in the gas/air phase cannot be kept low, a reduction in the riserpressure can be achieved by closing the subsea BOP and taking the returnthrough the equalizing loop, thereby reducing the pressure in the riser.This stems from the fact that the friction pressure from fluid flowingin the reduced diameter of the equalizing loop will increase the bottomhole pressure, hence a reduced pressure in the drilling riser will beachieved.

The present invention specifies a solution that allowsprocess-controlled drilling in a safe and practical manner.

DESCRIPTION OF THE DRAWINGS

These and other aspects of the present invention will be readilyapparent to those skilled in the art from a review of the followingdetailed description of a preferred embodiment in conjunction with theaccompanying drawings and claims. The drawings show in:

FIG. 1 a schematic overview of the arrangement.

FIG. 2 a schematic diagram of and partial detail of the arrangement ofFIG. 1.

FIG. 3 a schematic diagram of and partial detail of the arrangement ofFIG. 2.

FIG. 4: in schematic detail the use of a pull-in device to be usedtogether with the arrangement of FIG. 1.

FIG. 5 an ECD (or downhole) process control system flow chart.

FIG. 6 a diagram illustrating the benefits from the improved method ofdrilling through and producing from depleted formations.

FIG. 7 a diagram illustrating the benefits the effects of the improvedmethods of controlling hydraulic pressures in a well being drilled.

DETAILED DESCRIPTION OF THE INVENTION

In the following detailed description, taken in conjunction with theforegoing drawings, equivalent parts are given the same referencenumerals.

FIG. 1 illustrates a drilling platform 24. The drilling platform 24 canbe a floating mobile drilling unit or an anchored or fixed installation.Between the sea floor 25 and the drilling platform 24 is a high-pressureriser 6 extending, a subsea blowout preventer 4 is placed at the lowerend of the riser 6 at the seabed 25, and a surface blowout preventer 5is connected to the upper end of the high pressure riser 6 above orclose to sealevel 59. The surface BOP has surface kill and choke line58, 57, which is connected to the high pressure choke-manifold on thedrilling rig (not shown). The riser 6, does not require outside kill andchoke lines extending from subsea BOP to the surface. The subsea BOP 4has a smaller bypass conduit 50 (typically 1-4″ ID), which willcommunicate fluid between the well bore below a closed blowout preventer4 and the riser 6. The by-pass line (equalizing line) 50 makes itpossible to equalize between the well bore and the high pressure riser 6when the BOP is closed. The by-pass line 50 has at least one, preferablytwo surface-controllable valves 51, 52

The blowout preventer 4 is in turn connected to a wellhead 53 on top ofa casing 27, extending down into a well.

In the high pressure riser system a low riser return system (LRRS) risersection 2 can be placed at any location along the high pressure riser 6,forming an integral a part of the riser.

Near the lower end of the high pressure riser 6 a riser shutoff pressurecontainment element 49 is included, in order to close off the riser andcirculate the high pressure riser to clean out any debris, gumbo or gaswithout changing the bottom-hole pressure in the well. In addition it isalso possible to clean the riser 6 after it is disconnected from thesubsea BOP 4 without spillage to the ocean.

Between the drilling platform/vessel 24 and the high-pressure riser 6 ariser tension system, schematically indicated by reference number 9, isinstalled.

The high-pressure riser includes a remotely monitored an upper pressuresensor 10 a and a lower pressure sensor 10 b. The sensor output signalsare transmitted to the vessel 24 by, e.g., a cable 20, electronically orby fiber optics, or by radio waves or acoustic signals. The two sensors10 a and 10 b measure the pressure in the drilling fluid at twodifferent levels. Since the distance between the sensors 10 a and 10 bis predetermined, the density of the drilling fluid can be calculated. Aremotely monitored pressure sensor 10 c is also included in the subseaBOP 4, to supervise the pressure when the subsea BOP 4 is closed.

The high pressure riser 6 is a single bore high-pressure tubular and incontrary to traditional riser systems there is no requirement forseparate circulation lines (kill or choke lines) along the riser, to beused for pressure control in the event oil and gas has unexpectedlyentered the borehole 26. High pressure in the context of this inventionis high enough to contain the pressures from the subsurface formations,typically, 3000 psi (200 bars) or higher.

Included in the high pressure riser system is the low riser returnsection (LRRS) 2 that can be installed anywhere along the riser length,the placement depending on the borehole to be drilled and the sea-waterdepth on the location. The riser section 2 contains a high-pressurevalve 38 of equal or greater rating than the riser 6 and which can becontrolled through the rotary table on the drilling rig.

FIG. 1 also shows a drill string 29 with a drill bit 28 installed in theborehole. Near the bottom of the drill string 29 inside the string is apressure regulating valve 56. The valve 56 has the capability to preventU-tubing of drilling fluid into the riser 6 when the pumping stops. Thisvalve 56 is of a type that will open at a pre-set pressure and stay openabove this pressure without causing significant pressure loss inside thedrill string once opened with a certain flow rate through the valve.

An air compressor 70, a pump by which a pressure differential is createdor maintained by transferring a volume of air from one region toanother, is connected to the riser 6 above the surface BOP 6. Thecompressor 70 is capable of providing a sub-atmospheric pressure insideof the riser 6. Exhaust air, that may contain some amount of hydrocarboncan be led to the burner boom or other safe vent.

Included in the riser section 6 is an injection line 41, which runs backto the vessel/platform 24. This line 41 has a remotely operated valve 40that can be controlled from the surface. The inlet to the riser 6 fromthe line 41 can be anywhere on the riser 6. The line 41 can extendparallel to the lines of the low riser return pumping system that is tobe explained below.

The LRRS riser section 2 includes a drilling fluid return outlet 42 acomprising at least one or more high-pressure riser outlet valve 38 anda hydraulic connector hub 39. The hydraulic connector hub 39 connects alow riser return pumping system 1 (FIGS. 2 and 3) with the high-pressureriser 6.

The low riser return pumping system includes a set of drilling fluidreturn pumps 7 a and 7 b. The pumps are connected to the connector 39via a gumbo/debris box 8, an LRRS mandrel 36 and a drilling fluid returnsuction hose 31 with a controllable non return valve 37. A dischargedrilling fluid conduit 15 connects the pumps 7 a and 7 b with thedrilling fluid handling systems (not shown) on the platform 24. As shownin FIG. 4, the top of the drilling fluid return conduit 15 is terminatedin a riser suspension assembly 44 where a drilling fluid return outlet42 interfaces the general drilling fluid handling system on the platform24.

The pump system 1 is shown in greater detail in FIG. 2.

The high-pressure valves 11 a, b on the suction side of the pumps 7 a,b, and high-pressure valves 14 a, b and non return valves 13 a, b on thedischarge side of the pumps 7 a, b, controls the drilling fluid inletand outlet to the drilling fluid return pumps 7.

The gumbo debris box 8 includes a number of jet nozzles 22 and a jet andflushback line 21 with valves 12 to break down particle size in the box8.

The LRRS mandrel 36 includes a drilling fluid inlet port 16 and adrilling fluid pump outlet port 35. A stress taper joint 3a is attachedto either end of the LRRS mandrel 36.

As best shown in FIG. 2, the mud return pumps 7 a, 7 b are powered bypower umbilical 19 or by seawater lines of a hydraulic system.

The fluid path for the drilling fluid return goes from the outlet 42,though the hose 31, into the mandrel 36, out through the drilling fluidinlet port 16 and into the gumbo box 8. The pumps are pumping the fluidfrom the gumbo box 8 out through the mud pump outlet port 35 and intothe drilling fluid conduit 15 and back to the platform 24.

A dividing block/valve 33 is installed in the LRRS mandrel 36 acting asa shut-off plug between the mud return pump suction and discharge sides.The dividing valve/block 33 can be opened so as to dump debris into thegumbo box 8 to empty the return conduit 15 after prolonged pumpstoppage. A bypass line 69 with valves 32 can bypass the non-returnvalves 13 when valve 61 is shut, making it possible to gravity feeddrilling mud from the return conduit 15 into the riser 6 for riserfill-up purposes. Hence there are three riser fill-up possibilities, 1)From the top of the riser 2) through injection line 41 and throughbypass line 69. In this system design the injection line 41 might alsobe run alongside the return conduit and connected to the riser at valve40 with a ROV and /or to the bypass line 69.

The LRRS 1 is protected within a set of frame members forming a bumperframe 23.

By controlling the output of the pumps 7 a, b, the mud level 30 (theinterface between the drilling fluid and the air in the riser 6) in thehigh-pressure riser 6 can be controlled and regulated. As a consequencethe pressure in the bottom hole 26 will vary and can thus be controlled.

FIG. 3 shows in even greater detail the lower part of the pump system 1.The level of gumbo or other debris in the gumbo debris tank 8 iscontrolled by a set of level sensors 17 a, b connected to a gumbo debriscontrol line 18 running back to the vessel or platform 24.

Reference is now made to FIG. 4. On the platform or vessel 24 a handlingframe 43 for the discharge drilling fluid conduit 15 is installed. TheLRRS 1 is deployed into the sea by the discharge drilling fluid conduit15 or on cable until it reaches the approximate depth of the LRRS risersection 2. The system can also be run from an adjacent vessel (notshown) lying alongside the main drilling platform 24.

A pull-in assembly will now be described referring to FIG. 4. Attachedto the end of the drilling fluid suction hose 31 is a pull-in wire 47operated by a heave compensated pull-in winch 48. The pull-in wire 47runs through a suction hose pull-in unit and a sheave 46. The end of thesuction hose 31 is pulled towards the hydraulic connector 39 forengagement with the connector 39 by the pull-in assembly 46, 47, 48.

The drilling fluid suction hose 31 may be made neutrally buoyant bybuoyancy elements 45.

The control system for determining the ECD and calculation of theintended lifting or lowering of the liquid/gas interface in the riser 6will now be described referring to FIG. 5.

The bottom hole pressure is the sum of five components:P_(bh)=P_(hyd)+P_(fric)+P_(wh)+P_(sup)+P_(swp)Where:

-   P_(bh)=Bottom hole pressure-   P_(hyd)=Hydrostatic pressure-   P_(fric)=Frictional pressure-   P_(wh)=Well head pressure-   P_(sup)=Surge pressure due to lowering the pipe into the well-   P_(swp)=Swab pressure due to pulling the pipe out of the well

Controlling bottom hole pressure means controlling these fivecomponents.

The Equivalent circulation Density (ECD) is the density calculated fromthe bottom hole pressure P_(bh))ρ_(E) ·g·h=P _(bh)  (1)Where:

-   -   ρ_(E)=Equivalent Circulation Density (ECD) (kg/m3)    -   g=Gravitational constant (m/s²)    -   h=Total vertical depth (m)

For a Newtonian Fluid, the pressure in the annulus can be calculated asfollows assuming no wellhead pressure and no surge or swab effect:

$\begin{matrix}{P_{bh} = {{\rho_{m} \cdot g \cdot h} + \frac{128 \cdot \eta \cdot L_{1} \cdot Q}{\pi^{2} \cdot \left( {D_{0} - d_{ds}} \right)^{3} \cdot \left( {D_{0} + d_{ds}} \right)^{2}}}} & (2)\end{matrix}$

For a Bingham fluid, the following formula is used:

$\begin{matrix}{P_{b\; h} = {{\rho_{m} \cdot g \cdot h} + \frac{128 \cdot \eta \cdot L_{1} \cdot Q}{\pi^{2} \cdot \left( {D_{0} - d_{d\; s}} \right)^{3} \cdot \left( {D_{0} + d_{d\; s}} \right)^{2}} + \frac{16 \cdot \tau_{0} \cdot L_{1}}{3 \cdot \left( {D_{0} - d_{d\; s}} \right)}}} & (3)\end{matrix}$Where:

-   ρ_(m)=Density of drilling fluid being used-   η=Viscosity of drilling fluid-   L₁=Drillstring length-   Q=Flowrate of drilling fluid-   D₀=Diameter of wellbore-   d_(ds)=Diameter of drillstring-   g=Gravitational constant-   h=Total vertical depth-   τ₀=Yield point of drilling fluid

FIG. 5 is an is an illustration of parameters used to calculate theECD/dynamic pressure and the height (h) of the drilling fluid in themarine drilling riser using the low riser return and lift pump system(LRRS).

From eq. 4 (Newtonian Fluid ), it is seen that in order to keep thebottom hole pressure P_(bh)) constant, an increase in flowrate (Q)requires the hydrostatic head (h) to be reduced.

$\begin{matrix}{P_{bh} = {{\rho_{m} \cdot g \cdot h} + \frac{128 \cdot \eta \cdot L_{1} \cdot Q}{\pi^{2} \cdot \left( {D_{0} - d_{ds}} \right)^{3} \cdot \left( {D_{0} + d_{ds}} \right)^{2}} + P_{\sup} + P_{swp}}} & (4)\end{matrix}$

The expression for calculating swab and surge pressure is not shown inEq. 4. However, when moving the drillstring into the hole, an additionalpressure increase (P_(sup)) will take place due to the swab effect. Inorder to compensate for this effect, the hydrostatic head (h) and/or theflowrate (Q) would have to be reduced.

When moving the drill string out of the hole, a pressure (P_(swp)) dropwill take place due to the surge effect. In order to compensate for thiseffect, the hydrostatic head (h) and/or the flowrate (Q) would have tobe increased.

The swab and surge effects, are as described above, a result of drillstring motion. This motion is not caused due to tripping only, but alsodue to vessel motion when the drill string is not compensated, i.e. makeand break of the drill string stands.

FIG. 5 shows a flowchart to illustrate the input parameters to theconverter indicated above, for control of bottom hole pressure (BBP)using the low return riser and lift pump system (LRRS) described above.

Into the converter 100 a set of parameters are put. The well and pipedimensions 101, which are evidently known from the start, but may varydepending on the choice of casing diameter and length as the drilling isproceeding, the mud pump speed 102, which, e.g., may be measured by asensor at each pump, pipe and draw-work movement (direction and speed)103, which also may be measured by a sensor that, e.g., is placed on thedraw-work main winch, and the drilling fluid properties (viscosity,density, yield point, etc.) 104.

The parameters 101, 102, 103, 104 are entered as values into theconverter 100.

Additional parameters, such as bottom hole pressure 105, which may bethe result of readings from Measurements While Drilling (MWD) systems,actual mud weight (density) 106 in the drilling riser, preferablyresulting from calculations based on measurements by the sensors 10 aand 10 b, as explained above, etc., may also be collected before theneeded hydrostatic head (level of interface between drilling fluid andair) (h) to gain the intended bottom hole pressure is calculated.

The needed hydrostatic head (h) is input to a comparator/regulator 108

The fluid level (h′) in the riser is continuously measured and thisparameter 107 is compared with the calculated hydrostatic head (h) inthe comparator/regulator 108. The difference between these twoparameters is used by the comparator/regulator 108 to calculate theneeded increase or decrease of pump speed and to generate signals 109for the pumps to achieve an appropriate flow rate that will result in ahydrostatic head (h).

The above input and calculations may take place continuously orintermittently to ensure an acceptable hydrostatic head at all times.

Referring to FIGS. 6 and 7 some effects of the present invention on thepressure will be explained. In the figures the vertical axis is thedepth from sea level, with increasing depth downward in the diagrams.The horizontal axis is the pressure. At the left hand side the pressureis atmospheric pressure and increasing to the right.

In FIG. 7 the line 303 is the hydrostatic pressure gradient of seawater.The line 306 is the estimated pore pressure gradient of the formation.In conventional drilling the mud weight gradient 305 indicates that acasing 310 have to be set in order to stay in between the expected porepressure and the formation strength—the formation strength at this pointbeing indicated by reference number 309—at the bottom of the last casing315. If drilling with an arrangement and method according to the presentinvention, the gradient of the mud can be higher, as indicated by theline 310, which means that one can drill deeper.

If however, the pore pressure, indicated by 312, at some point shouldexceed the expected pressure, indicated by 311, a kick could occur. Withthe method of present invention the level can be dropped further, downto 302 and the mud weight further increased. The net result is apressure decrease at the casing shoe 309 with an increase in pressurenear the bottom of the hole, as indicated by 307, making it possible todrill further before having to set a casing.

In this way it is possible to reduce the pressure on weak formationshigher up in the hole and compensate for higher pore pressures in thebottom of the hole. Thus it is possible to rotate the pressure gradientline from the drilling mud around a fixed point, for example the seabedor a casing shoe.

Another example of the ability of this system is shown in FIG. 6. Inthis situation a severely depleted formation 210 is to be drilled. Theformation has been depleted from a pressure at 205 at which it waspossible to drill using a drilling fluid slightly heavier than seawater(1,03 SG) as drilling fluid, with a pressure gradient shown at 203. Thefracture gradient of the depleted formation is now reduced to 211, whichis lower than the pressure gradient of seawater from the surface, asindicated by the line 201.

With the present invention drilling can be done without needing reducethe density of the drilling fluid substantially and having to turn thedrilling fluid into gas, foam or other lighter than water drillingsystems, as shown by the pressure gradient 214.

By introducing an air column in the upper part of the riser the upperlevel of the drilling fluid can be dropped down to a level 202. Ea thecase shown a drilling fluid with the same pressure gradient as seawater201 can be used, but starting at a substantially lower point, as shownby 202.

A pore pressured of 0,7 SG can be neutralized by low liquid level withseawater of 1,03 SG as shown by 202. This ability gives rise to greatadvantages when drilling in depleted fields, since reducing the originalformation pressure of 1,10 SG at 205 to 0,7 SG at 210 by production, canalso give rise to reduced formation fracture pressure, shown at 211,that can not be drilled with seawater from surface, as shown by 201.With the present invention the bottom-hole pressure exerted by the fluidin the well bore can be regulated to substantially below the hydrostaticpressure for water. With the prior art of drilling arrangements thiswill require special drilling fluid systems with gases, air or foam.With the present invention this can be achieved with a simple seawaterdrilling fluid system.

It should be apparent that many changes may be made in the various partsof the invention without departing from the spirit and scope of theinvention and the detailed embodiments are not to be considered limitingbut have been shown by illustration only. Other variations will no doubtoccur to those skilled in the art upon the study of the detaileddescription and drawings contained herein. Accordingly, it is to beunderstood that the present invention is not limited to the specificembodiments described herein, but should be deemed to extend to thesubject matter defined by the appended claims, including all fairequivalents thereof.

1. A drilling system for compensating for changes in equivalent mudcirculation density (ECD) or dynamic pressure in an annulus bore in awell resulting from drilling activities during subsea drilling at greatwater-depths, comprising: a high pressure drilling riser extending froma seafloor wellhead to near the surface; a near surface BOP at the upperend of the drilling riser, the near surface BOP having an upper highpressure line; a subsea outlet in communication with the interior of theriser at a point above the seafloor wellhead; a flow return conduitrunning back to the surface; a pumping system suspended above theseafloor and connecting said subsea outlet to said flow return conduit;a valve adapted to isolate the riser from the pumping system; means forconverting changes in pressure in said riser to an equivalent change inheight of drilling fluid in the riser; means for adjusting the pump rateof said pumping system according to the difference of the height ofdrilling fluid in said riser and said equivalent change in height ofdrilling fluid; thereby adjusting the height of drilling fluid in thedrilling riser so as to neutralize the changes in pressure in saidannulus bore created by said drilling activities by varying the actualamount of drilling fluid in the riser; a subsea shut-off device at thesea floor, the shut off device having at least one by-pass lineproviding communication between the well below the shut-off device andthe interior of the riser, the by-pass line containing at least oneshut-off valve.
 2. A system according to claim 1, further comprising agas bleeding outlet connected to a choke line in communication with ahigh pressure choke and stand pipe manifold on a drilling vessel.
 3. Asystem according to claim 1, wherein the pumping system with flow returnline is adapted to be launched and run with the riser.
 4. A systemaccording to claim 1, further comprising a filling line coupled to theriser substantially below sea level and above said subsea outlet, thefilling line being adapted for filling the riser with a gas or liquid.5. A system according to claim 4, wherein the gas is an inert gas fordisplacement of the air above the drilling fluid.
 6. A system accordingto claim 1, further comprising a valve in the flow return conduit, and aparticle collection box in the flow return line, the valve being adaptedfor opening and closing the communication between the particlecollection box and the flow return conduit.
 7. A system according toclaim 6, wherein the particle collection box is hanging underneath thepumping system and the particle collection box has a re-circulation andjetting means for breaking down particle size to prevent particle buildup.
 8. A method for compensating for equivalent mud circulation density(ECD) or dynamic pressure increase or decrease in an annulus bore in awell during subsea drilling at great water-depths resulting fromdrilling activities, comprising the steps: maintaining the pressure inthe top of a drilling riser extending from a seafloor wellhead to thesurface at equal to or lower than atmospheric pressure, said riserconfigured with a seabed BOP and bypass; converting a change in pressurein the well created by drilling activities to an equivalent change inheight of drilling fluid in the riser; adjusting the pump rate of adrilling fluid return pump suspended above the seafloor and connected ata point above the seafloor wellhead to the drilling riser so as toadjust the height of drilling fluid in the drilling riser by theequivalent change in height of drilling fluid so as to neutralize thechange in pressure created by the drilling activities by varying theactual amount of drilling fluid in the riser.
 9. A method according toclaim 8, wherein gas escaping from an underground formation is separatedfrom liquid during offshore drilling, comprising the steps: permittinggas and drilling fluid in a drilling riser extending from a seafloorwellhead to the surface to form a gas/liquid interface within thedrilling riser; providing a liquid outlet below the gas/liquid interfacelevel and substantially above the seafloor wellhead, said outlet beingconnected to a pumping system suspended above the seafloor and hence toa return conduit, providing a gas outlet above the gas/liquid interfacelevel, closing a near surface BOP at the upper end of the drillingriser, and pumping liquid out of the drilling riser through the liquidoutlet, whereby the drilling riser is acting as a gas separator.
 10. Amethod according to claim 9, wherein a flow return line between theliquid outlet and the pumping system is adapted to prevent free gas fromentering the return conduit by having a U-shaped loop acting as agas-lock.
 11. A method according to claim 10, where the height of thegas-lock can be adjusted by varying the subsea level of the pumpingsystem.
 12. A method according to claim 9, wherein the level of thegas/liquid interface between the drilling fluid and the gas in thedrilling riser is maintained below sea level so that the pressure in thebottom of the well is lower than the hydrostatic pressure exerted byseawater from sea level.
 13. A method according to claim 12, wherein thedrilling riser comprises sensors for monitoring the height of thegas/liquid interface level in the riser, the sensors being coupled to aregulating means controlling the pump rate of the pumping system andthereby controlling the height of the gas/liquid interface level.
 14. Amethod according to claim 8, said change in pressure occurring in saidriser by drilling activities comprising a change in pressure created bythe drill string being moved up or down in the well.
 15. A methodaccording to claim 8, said change in pressure in said drilling riserbeing created by circulation of drilling fluid through the bit.
 16. Amethod for controlling equivalent mud circulation density (ECD) in awell during subsea drilling operations, comprising: using a highpressure drilling riser extending from a seafloor wellhead and subseaBOP to the surface, within which there is drilling fluid present, therebeing no outside kill or choke lines extending from the surface to thesubsea BOP, said subsea BOP configured with a bypass; maintaining thepressure in the top of the drilling riser at equal to or lower thanatmospheric pressure; monitoring the height of drilling fluid in theriser; monitoring bottom hole pressure in the well for a change inpressure; calculating an equivalent change in height of drilling fluidto the change in pressure; using a drilling fluid pump suspended abovethe seafloor and connected to the riser substantially above the seafloorwellhead and below the height of drilling fluid, adjusting the height ofdrilling fluid in the riser by the equivalent change in height ofdrilling fluid, thereby adjusting the drilling fluid level in thedrilling riser so as to reverse the change in the bottom hole pressure.17. A drilling system for controlling equivalent mud circulation density(ECD) in a well resulting from drilling activities during subseadrilling operations, comprising: a high pressure drilling riserextending from a seafloor wellhead to the surface and having a surfaceBOP at the upper end of the drilling riser, the surface BOP having anupper high pressure line, there being no kill or choke lines extendingfrom the surface to the seafloor wellhead; a subsea outlet incommunication with the interior of the riser at a point above theseafloor wellhead; a flow return conduit running back to the surface; apumping system suspended above the seafloor and connecting the subseaoutlet to the flow return conduit; a valve adapted to isolate the riserfrom the pumping system; means for monitoring the height of drillingfluid in the drilling riser; means for sensing a change in pressure inthe drilling riser; means for converting the change in pressure in thedrilling riser to an equivalent change in height of drilling fluid inthe riser; means for adjusting the pump rate of the pumping systemaccording to the difference of the height of drilling fluid in thedrilling riser and the equivalent change in height; thereby adjustingthe height of drilling fluid in the drilling riser so as to neutralizethe change in pressure by varying the actual amount of drilling fluid inthe riser; and a subsea shut-off device at the sea floor; the shut offdevice having at least one by-pass line providing communication betweenthe well below the shut-off device and the interior of the riser, theby-pass line containing at least one shut-off valve or pressureregulating valve.